U.S. patent application number 14/890625 was filed with the patent office on 2016-05-05 for downhole tool and method to boost fluid pressure and annular velocity.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is HALLIBURTON ENERGY SERVICES INC.. Invention is credited to Alan William Marr.
Application Number | 20160123098 14/890625 |
Document ID | / |
Family ID | 52346585 |
Filed Date | 2016-05-05 |
United States Patent
Application |
20160123098 |
Kind Code |
A1 |
Marr; Alan William |
May 5, 2016 |
DOWNHOLE TOOL AND METHOD TO BOOST FLUID PRESSURE AND ANNULAR
VELOCITY
Abstract
A disclosed embodiment of a downhole tool includes a pump that
is powered by rotation of the drill string to increase fluid
pressure during downhole circulation.
Inventors: |
Marr; Alan William;
(Arbroath, Angus, GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES INC. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
52346585 |
Appl. No.: |
14/890625 |
Filed: |
July 16, 2013 |
PCT Filed: |
July 16, 2013 |
PCT NO: |
PCT/US2013/050731 |
371 Date: |
November 12, 2015 |
Current U.S.
Class: |
175/57 ;
175/317 |
Current CPC
Class: |
E21B 21/00 20130101;
F04D 13/14 20130101; E21B 4/006 20130101; E21B 21/08 20130101 |
International
Class: |
E21B 21/08 20060101
E21B021/08; F04D 13/14 20060101 F04D013/14 |
Claims
1. A tool for boosting fluid pressure downhole, the tool
comprising: a tool housing configured for coupling to a drill
string, the tool housing defining a fluid flow passage; a sleeve
rotatably positioned around the tool housing, the sleeve comprising
one or more gripping members on an outer portion of the sleeve
configured to grip a wellbore wall; a drive shaft passing through
the tool housing and having a central gear; at least one drive gear
rotatably coupled to the sleeve, the at least one drive gear
meshing both with an inner portion of the sleeve and with the
central gear; and a pump mechanism coupled to the drive shaft to
receive power imparted by rotation of the drive shaft, the pump
configured to increase a fluid pressure within the flow
passage.
2. The tool as defined in claim 1, wherein the pump comprises a
multi-stage impeller assembly.
3. The tool as defined in claim 1, wherein the at least one drive
gear is rotatably coupled about an axis parallel to an axis of the
tool housing.
4. The tool as defined in claim 1, further comprising: a plurality
of teeth along the inner portion of the rotating sleeve; a
plurality of teeth on the at least one drive gear; and a plurality
of teeth on the central gear of the drive shaft, wherein the teeth
on the at least one drive gear mesh both with the teeth along the
inner portion of the rotating sleeve and the teeth on the central
gear.
5. The tool as defined in claim 4, wherein the at least one drive
gear comprises a plurality of drive gears circumferentially spaced
about the drive shaft.
6. The tool as defined in claim 1, further comprising a plurality
of offset elements defining a fluid flow channel about the one or
more gripping member.
7. A tool for boosting fluid pressure downhole, the tool
comprising: a tool housing which rotates in relation to a wellbore
wall, the tool housing defining a flow passage in which fluid can
flow; a drive gear comprising: a first friction transfer element
having a portion which extends out from the tool housing and a
portion which extends into the tool housing; and a second friction
transfer element having a portion which extends out from the tool
housing and a portion which extends into the tool housing, wherein
the portions of the first and second friction transfer elements
that extend out from the tool housing grip the wellbore wall to
create a rotational force when the tool housing is rotated; a drive
shaft operationally coupled to the first and second friction
transfer elements whereby, during rotation of the tool housing, the
first and second friction transfer elements transfer the rotational
force to the drive shaft, thereby resulting in rotation of the
drive shaft; and a pump mechanism positioned along the flow passage
and operationally coupled to the drive shaft to thereby receive the
rotational force imparted by the drive shaft, thus driving the pump
mechanism to boost a pressure of fluid traveling through the flow
passage.
8. The tool as defined in claim 7, wherein the first and second
friction transfer elements are friction balls.
9. The tool as defined in claim 7, wherein the first and second
friction transfer elements rotate on an axis parallel to an axis of
the tool housing during rotation of the tool housing.
10. The tool as defined in claim 1 or 7, wherein the wellbore wall
is cased.
11. The tool as defined in claim 1 or 7, wherein the tool forms
part of a drilling or completion assembly.
12. A method for boosting fluid pressure in a wellbore, the method
comprising: positioning a downhole tool at a desired location along
the wellbore, whereby fluid travels through a flow passage of the
downhole tool; rotating the downhole tool in relation to an
opposing surface to produce a rotational force; and utilizing the
rotational force to drive a pump mechanism to thereby boost a
pressure of the fluid traveling through the downhole tool.
13. The method as defined in claim 12, further comprising
increasing an annular velocity of the fluid in response to the
pressure boost.
14. The method as defined in claim 12, wherein rotating the
downhole tool to produce the rotational force further comprises:
gripping the opposing surface using a rotating sleeve positioned
around the downhole tool; rotating the downhole tool while the
rotating sleeve remains stationary; rotating a drive gear
operationally coupled to the rotating sleeve in response to
rotation of the downhole tool; and rotating a drive shaft
operationally coupled to the drive gear in response to rotation of
the drive gear.
15. The method as defined in claim 14, wherein driving the pumping
mechanism further comprises driving the pumping mechanism in
response to the rotation of the drive shaft.
16. The method as defined in claim 12, wherein rotating the
downhole tool to produce the rotational force further comprises:
gripping the opposing surface using a friction transfer element
positioned along the downhole tool; rotating the downhole tool;
rotating the friction transfer element in response to rotation of
the downhole tool; and rotating a drive shaft operationally coupled
to the friction transfer element in response to rotation of the
friction transfer element.
17. The method as defined in claim 12, further comprising forcing
the fluid out of the downhole tool and up through an annulus formed
between the downhole tool and the opposing surface.
18. The method as defined in claim 13 or 16, wherein gripping the
opposing surface further comprises gripping a surface of a casing,
liner or formation.
19. The method as defined in claim 12, wherein positioning the
downhole tool at the desired location along the wellbore further
comprises deploying the downhole tool as part of a drilling or
completion assembly.
Description
FIELD OF THE DISCLOSURE
[0001] The present disclosure relates generally to the circulation
of drilling and completion fluids and, more specifically, to a
downhole tool which imparts additional energy to such fluids during
circulation.
BACKGROUND
[0002] A hydrocarbon recovery well may be drilled by rotating a
drill string, which is an assembly that generally includes a
plurality of interconnected drill pipe segments having a drill bit
and bottom hole assembly ("BHA") at a lower end. As the well is
drilled, the drill bit generates cuttings and other debris. In
downhole drilling operations, fluid circulation is commonly used
for wellbore cleaning and solids transport, such as to remove the
cuttings and other debris. In general, circulation involves pumping
fluid down the drill string (using a mud pump at the surface) and
back up the annulus between the drill string and a wellbore wall.
The speed at which the fluid moves along the annulus is referred to
as the annular velocity. Thus, it is important to monitor the
annular velocity to ensure proper wellbore cleaning, solid
transport, as well as to avoid erosion of the wellbore wall.
[0003] The fluid annular velocity is adversely affected in a number
of ways. For example, during circulation, pressure drops occur in
the circulating system due to frictional losses inside the tubing
and the annulus, as well as the differential hydrostatic pressure
between the tubing and annulus. The maximum pressure is generated
at the mud pump manifold (the standpipe pressure ("SPP")) and the
lowest pressure is generated at the fluid returns (atmospheric
pressure for open returns or applied choke pressure for managed
pressure operations). Thus, the fluid velocity is limited by the
maximum SPP. As a result, in some instances, the annular velocity
may not be high enough to sufficiently clean the wellbore. However,
if the fluid pressure is somehow increased during circulation, the
SPP can be reduced. In turn, this would permit an increase in the
maximum pump rate which produces higher annular velocities.
[0004] Accordingly, in view of the foregoing, there is a need in
the art for a method to increase the fluid annular velocity.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] FIG. 1 illustrates a circulation system for drilling
operations, according to certain exemplary embodiments of the
present disclosure;
[0006] FIG. 2A is a sectional view of a downhole tool, according to
certain exemplary embodiments of the present disclosure;
[0007] FIG. 2B illustrates a cut-away view of a gear ring located
along the inner surface of the rotating sleeve of a downhole tool,
in accordance to certain exemplary embodiments of the present
disclosure;
[0008] FIG. 2C is a three-dimensional view of a downhole tool which
includes a plurality of offset gripping members, in accordance to
certain exemplary embodiments of the present disclosure;
[0009] FIG. 2D is a sectional topside view of a downhole tool taken
along line 2D of FIG. 2A;
[0010] FIG. 3A illustrates an alternative embodiment of a drive
mechanism used in a downhole tool, according to certain exemplary
embodiments of the present disclosure; and
[0011] FIG. 3B illustrates a three-dimensional external view of the
downhole tool of FIG. 3A.
DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
[0012] Illustrative embodiments and related methodologies of the
present disclosure are described below as they might be employed in
a downhole tool which boosts fluid annular pressure during
circulation, thus permitting higher fluid annular velocities. In
the interest of clarity, not all features of an actual
implementation or methodology are described in this specification.
Also, the "exemplary" embodiments described herein refer to
examples of the present disclosure. It will of course be
appreciated that in the development of any such actual embodiment,
numerous implementation-specific decisions must be made to achieve
the developers' specific goals, such as compliance with
system-related and business-related constraints, which will vary
from one implementation to another. Moreover, it will be
appreciated that such a development effort might be complex and
time-consuming, but would nevertheless be a routine undertaking for
those of ordinary skill in the art having the benefit of this
disclosure. Further aspects and advantages of the various
embodiments and related methodologies of the disclosure will become
apparent from consideration of the following description and
drawings.
[0013] As described herein, exemplary embodiments of the present
disclosure are directed to an in-line downhole tool driven by the
drill string rotation in order to drive a pump mechanism that
boosts fluid pressure during circulating, thus permitting an
increase in annular velocity. One disclosed embodiment of a
downhole tool comprises a drive mechanism that includes a drive
gear and drive shaft in order to harness a torque (i.e. a
rotational force) created by rotating the drill string. As used
herein, the term "gear" broadly refers to any rotational member
having a surface along a periphery configured to engage with a
surface along the periphery of another rotational member. In the
example embodiments discussed below, the gears described may be
conventional gears having a plurality of teeth configured to mesh
with a corresponding plurality of teeth on the other rotational
member (e.g. another gear or a gear ring). However, such a gear may
alternatively comprise, for example, a surface on the periphery of
the gear that, without the use of conventional gear teeth,
frictionally meshes with a corresponding surface on the other
rotational member, such that rotation of one causes rotation of the
other without the use of teeth. The surfaces for frictionally
engaging one another may be imparted with a high coefficient of
friction, such as by roughening the surfaces or applying a
frictional material such as a rubber compound. In response to
rotation of the drill string, the drive gear rotates to transfer
power (via application of a torque) to a drive shaft coupled to the
pump mechanism. The drive shaft rotates in response to the applied
torque, to then transmit power from the drive shaft to the pump
assembly a to drive the pump assembly, to boost the pressure of
fluid traveling through the downhole tool. These and other features
of the present disclosure will be described in further detail
below.
[0014] FIG. 1 illustrates a circulation system for drilling
operations, according to certain exemplary embodiments of the
present disclosure. Drilling system 100 (rotary-type, for example)
includes a drilling rig 102 located at a surface 104 of a wellbore.
Drilling rig 102 provides support for a drill string 108. Drill
string 108 penetrates a rotary table 110 for drilling a wellbore
112 through subsurface formations. In this exemplary embodiment,
drill string 108 includes a Kelly 116 (in the upper portion) and a
bottom hole assembly 120 located at the lower portion of drill
string 108. Bottom hole assembly 120 includes a drill collar 122, a
downhole tool 124 to boost fluid pressure, and a drill bit 126.
Additionally, although not shown, bottom hole assembly 120 may
comprise any number of other downhole tools such as, for example,
Measurement While Drilling (MWD) tools, Logging While Drilling
(LWD) tools, etc.
[0015] During drilling operations, the drill string 108 and the
bottom hole assembly 120 are rotated by the rotary table 110 or a
top drive, as generally understood in the art apart from the
specific teachings of this disclosure. In other embodiments, such
as in directional drilling applications, a drill bit may
alternatively be rotated by a motor (not shown) that is positioned
downhole. Drill collar 122 may be used to add weight to the drill
bit 126 and to stiffen bottom hole assembly 120, thus allowing
bottom hole assembly 120 to transfer the weight to drill bit 126.
Accordingly, this weight provided by the drill collar 122 also
assists drill bit 126 in the penetration of the surface 104 and the
subsurface formations.
[0016] During drilling operations, a mud pump 132 may pump drilling
fluid (known as "drilling mud") from a mud pit 134 through a hose
136, into the drill pipe (located along drill string 108), through
downhole tool 124, and down to drill bit 126. As described herein,
exemplary embodiments of downhole tool 124 are used to harness the
rotation of the drill string in order to power a pump mechanism
that increases the pressure of the fluid as it travels through
downhole tool 124. The drilling fluid can then flow out from drill
bit 126 and return back to the surface through an annular area 140
between drill string 108 and the sides of the wellbore 112 (i.e.,
circulation). The drilling fluid may then be returned to mud pit
134, where such fluid is filtered. Accordingly, the drilling fluid
can cool drill bit 126 as well as provide for lubrication of drill
bit 126 during the drilling operation. Additionally, the drilling
fluid removes the cuttings of the subsurface formations created by
drill bit 126.
[0017] With reference to FIG. 2A, certain exemplary embodiments of
downhole tool 124 will now be described in detail. FIG. 2A is a
sectional view of downhole tool 124 positioned along a drill
string. Alternatively, however, downhole tool 124 may also be used
in other bottom hole assemblies in which fluid circulation in
conducted, such as, for example, a completion assembly. Downhole
tool 124 includes a tool housing 141 defining a fluid flow passage
(referred to herein as a "bore") 142 extending through, in which
fluids (drilling or completion fluid, for example) may flow. A
drive mechanism 144 is positioned along bore 142. The drive
mechanism 144 includes, by way of example, two drive gears 146a and
146b positioned along tool housing 141 and opposite one another
with respect to a drive shaft 148. Drive shaft 148 is operationally
coupled to drive gears 146a,b via a central gear 150 located at its
upper end. In this exemplary embodiment, drive gears 146a,b mesh
with another gear, referred to herein as a "central gear" 150 in
order to transfer rotational force to drive shaft 148.
[0018] A pump mechanism 152 is operationally coupled to drive shaft
148 in order to receive power via an applied torque imparted by
drive shaft 148. In turn, pump mechanism 152 uses the rotation of
the drive shaft 148 to drive the pump 152 to thereby increase the
pressure of fluid traveling through downhole tool 124, with a
corresponding increase in the fluid annular velocity. In certain
embodiments, drive shaft 148 forms a part of pump mechanism 152,
while in other embodiments the drive shaft 148 may be a separate
component not included with the pump mechanism 152, but
operationally coupled to another rotating member of the pump
mechanism 152, to power the pump 150. In this exemplary embodiment,
pump mechanism 152 is a multi-stage impeller assembly comprising a
plurality of impeller plates 154 arranged in series to one another.
Alternatively, other pumping mechanisms may be used, such as, for
example, a turbine, jet pump, or another centrifugal-type pump.
Centrifugal-type pumps are especially beneficial because it will
produce additional hydraulic pressure, relieve some of the
standpipe pressure, and may still be used if the in-line pump drive
failed.
[0019] Still referring to the exemplary embodiment of FIG. 2A,
drive mechanism 144 also includes a sleeve 156 positioned around
tool housing 141. The outer surface of sleeve 156 includes one or
more gripping members 158 to engage the wall of wellbore 112 such
that sleeve 156 remains stationary during rotation of tool housing
141 during circulation operations. In certain exemplary
embodiments, the diameter of sleeve 156 is selected such that it
vertically slides up/down along the wall of wellbore 112 during
deployment and retrieval of bottom hole assembly 120, while also
preventing the rotation of sleeve 156 when drill string 108 is
rotated. The proper diameter can be determined, for example, using
the internal diameter of the casing or wellbore.
[0020] A mechanical seal 160 is positioned around tool housing 141
at the upper and lower ends of sleeve 156 to provide protection
against leakage of fluids from annulus 140 into the area
surrounding drive gears 146a,b. The seals may be made of, for
example, metal, plastic or ceramic materials. A gear ring 162 is
located along the inner surface of sleeve 156, as shown in FIG. 2B.
Gear ring 162 comprises a series of teeth secured to or integrally
formed with the sleeve 152, which mesh with teeth positioned along
the periphery of each of the drive gears 146a,b. Drive gears 146a,b
are rotatably coupled to the tool housing 141 each about a
respective axis, such as using pins 164, thus allowing drive gears
146a,b each to rotate on an axis parallel to the axis of tool
housing 141 during rotation of drill string 108. Accordingly, when
drill string 108 (along with tool housing 141) is rotated while
sleeve 156 grips the wall of wellbore 112, power is transferred
from the drill string 108 to the drive mechanism 144 to power
pumping mechanism 152. Specifically, as further described below
with respect to FIGS. 1-2D, rotation of the drill string 108
rotates the tool housing 141 as the same angular rate as the drill
string 108. The rotation of the tool housing 141 causes the drive
gears 146a, 146b to roll along the gear ring 162, with a
corresponding rotation of the drive gears 146a, 146b about their
own axes as rotatably coupled to the tool housing 141. The rotation
of the drive gears 146a, 146b about their axes powers rotation to
the central gear 150, which drives the pump.
[0021] Note that in this embodiment, the positioning of the two
drive gears 146a, 146b opposite is one another with respect to
drive shaft 148 helps balance lateral forces to minimize or avoid
any lateral forces on the drive shaft 148, i.e. transverse to the
axis of rotation of the drive shaft 148. It should be understood,
however, that other embodiments may use a different number of drive
gears circumferentially spaced about the drive shaft 148 and meshed
with the central gear 150. Even an embodiment with a single drive
gear positioned between the gear ring 162 and the central drive
gear 150 is feasible, even though the above-described lateral force
balancing of multiple drive gears may not be provided by such a
single drive-gear embodiment.
[0022] As previously described, drive gears 146a,b may take the
form of toothed members, with each gear positioned along tool
housing 141 and rotatably secured for rotation about a respective
gear axis of that gear. As shown in FIG. 2A, drive gears 146a,b
each include a portion which extends out from tool housing 141 and
a portion which extends into tool housing 141. Central gear 150 of
drive shaft 148 is positioned between drive gears 146a and 146b,
and it includes teeth which mesh with the teeth of drive gears
146a,b such that, during rotation of drill string 108, the
generated rotational force is transmitted from drive gears 146a,b
to drive shaft 148.
[0023] As also previously described, the outer surface of
rotational sleeve 156 comprises a gripping member 158 that engages
the wall of wellbore 112. The profile of gripping member 158 is
designed such that it allows vertical movement of bottom hole 120
along wellbore 112 (using the weight of the drill string, for
example), while also preventing rotational movement of sleeve 156.
Although not shown, in certain embodiments, gripping member 158 may
be an engaging plate mounted on bow springs which exert force
outwardly such that contact is maintained between the plate and the
wall of the casing or wellbore. The bow spring can be selected to
apply the force necessary in any given application, as would be
understood by those ordinarily skilled persons described herein.
Alternatively, a casing scraper or other similar device may be used
in place of the spring to ensure the gripping member remains secure
against the wall.
[0024] In addition, gripping members 158 may be configured such
that, although rotating sleeve is in intimate contact with the wall
of wellbore 112, the annular flow path of annulus 140 is still
maintained so that circulation operations may be conducted. To
achieve this, gripping member 158 may take a variety of forms
including, but not limited to, angled blades as shown in FIG. 1 or
a plurality of offset elements as shown in FIG. 2C which form a
fluid flow channel around gripping members 158. FIG. 2C is a
three-dimensional view of downhole tool 124 which includes a
plurality of exemplary offset gripping members 158.
[0025] To illustrate the flow of fluid during circulation, FIG. 2D
is provided which illustrates a sectional topside view of downhole
tool 124 taken along line 2D of FIG. 2A. Here, gripping members 158
are engaged to the wall 113 of wellbore 112 such that sleeve 156 is
rotationally immobilized (i.e., it cannot rotate). Wall 113 may be
a casing, liner or formation surface, as the present disclosure is
useful in cased and open-hole applications. During an exemplary
circulation operation, fluid is pumped down through internal flow
area 166 (bore 142), past drive mechanism 144, and into pumping
mechanism 152 whereby the pressure of the fluid is increased, which
provides increased annular velocities. Thereafter, the fluid is
forced out the bottom of bottom hole assembly 120, around sleeve
156 as shown, and back up annulus 140.
[0026] Now that the various components of an exemplary downhole
tool 124 have been described, an exemplary methodology utilizing
downhole tool 124 will now be described with reference to FIGS.
1-2D. During a drilling operation, for example, drill string 108 is
lowered into wellbore 112 until a desired location is reached. As
drill bit 126 drills the formation, gripping member 158 allows
sleeve 156 to vertically slide along the wall of wellbore 112.
[0027] However, when drill string 108 is rotated, gripping members
158 engage the wall, thus immobilizing sleeve 156. Thereafter, as
fluid L (FIG. 2A) flows through drill string 108 (being pumped by
mud pump 132) and through internal flow area 166, drill string 108
is rotated such that tool housing 141 is also rotated, thus
creating a rotational force. As tool housing 141 rotates, drive
gears 146a,b begin to rotate along pins 164 as its teeth mate with
rotationally immobilized gear ring 162 of sleeve 156.
[0028] As drive gears 146a,b continue to rotate, they transfer the
rotational force to central gear 150 of drive shaft 148, thus
causing it to rotate. As drive shaft 148 rotates, it then transfers
the rotational force to pump mechanism 152, thereby rotating
impeller plates 154 which increases the pressure of fluid L as it
flows through each plate 154, as will be understood by those
ordinarily skilled in the art having the benefit of this
disclosure. Fluid L then flows through bearing support 155 coupled
to the lower end of pump mechanism 152. Bearing support 155
comprises three or four radial arms (not shown) which extend
outwardly (akin to wheel spokes), such that a plurality of flow
channels 157 are formed which allow Fluid L to flow therethrough.
Fluid L is then forced down through drill collar 122, out of drill
bit 126, up annulus 140 (around sleeve 156), and back to surface
104 for further circulation processing. Accordingly, rotation of
drill string 108 is used to produce a rotational force that is
harnessed by downhole tool 124 in order to increase the pressure of
the circulating fluid, thus permitting higher annular velocities.
Moreover, since sleeve 156 allows vertical movement of bottom hole
assembly 120, bottom hole assembly 120 can be moved up or down
wellbore 112 as desired while also boosting of the fluid
pressure.
[0029] FIG. 3A illustrates an alternative embodiment of drive
mechanism 144, according to certain exemplary embodiments of the
present disclosure. In this embodiment, no sleeve is used; instead,
a first and second friction transfer element 168a,b is used in
place of drive gears 146a,b, respectively. A mechanical seal 170 is
positioned around first and second friction elements 168a,b in
order to prevent fluid leakage. As previously described, first and
second friction transfer elements are secured to tool housing 141
using pins 164. Thus, a portion of first and second friction
transfer elements 168a,b extends out from tool housing 141, while
another portion extends into tool housing 141. The diameter
spanning from transfer element 168a to 168b is selected such that a
sufficient amount of friction is provided between friction transfer
elements 168a,b and the wellbore wall to create the rotational
force. Since friction transfer elements 168a,b are spaced around
tool housing 141, fluid is allowed to flow past them during
circulation, as shown in FIG. 3B which illustrates a
three-dimensional external view of downhole tool 124.
[0030] The portions of the first and second friction transfer
elements 168a,b which extends out of tool housing 141 engage the
wall of wellbore 112. In this example, central gear 150 may
comprise teeth along its outer diameter or may also be a
friction-type surface sufficient to transfer rotational force. When
drill string 108 is rotated, first and second friction transfer
elements 168a,b begin to rotate along pins 164, thus creating a
rotational force that is transferred to central gear 150 as
previously described. In turn, pump mechanism 152 is powered as
described above. Friction transfer elements 168a,b may be, for
example, polymer or metal friction balls or some other suitable
friction transfer element. In addition, the flow of fluid through
downhole tool 124 of FIGS. 3A-3B, around first and second friction
transfer elements 168a,b, and back up annulus 140 are the same as
described in previous embodiments. Accordingly, rotation of drill
string 108 is used to produce a rotational force that is harnessed
by downhole tool 124 in order to increase the pressure of the
fluid.
[0031] Accordingly, through use of the present disclosure, the
power of drill string rotation is harnessed in order to drive a
pump mechanism which increases the pressure of the circulating
fluid, thus permitting higher annular velocities. Thus, higher pump
rates are provided beyond that supplied by traditional mud pumps.
Additionally, through use of the present disclosure, the standpipe
pressure may be reduced, thus increasing the overall pressure drop
in the circulating system, thereby allowing the mud pumps to
operating at a faster rate. Such increased fluid pressure may be
used to increase the maximum pump rate and annular velocity, for
example, to enhance hole cleaning while drilling and casing
cleaning during displacement operations.
[0032] Exemplary embodiments of the downhole tools described herein
are particularly useful in, for example, displacement operations
whereby the tool is secured against a casing or liner.
Alternatively, the downhole tool may be used in drilling
operations, whereby the tool is secured up against a rock
formation. In the latter embodiment, the downhole tool may be
positioned in close proximity to the bottom of the drill string to
maximize the increase in annular velocity, such as, for example,
roughly 95 feet away from the bit.
[0033] An exemplary embodiment of the present disclosure provides a
tool for boosting fluid pressure downhole, the tool comprising a
tool housing configured for coupling to a drill string, the tool
housing defining a fluid flow passage; a sleeve rotatably
positioned around the tool housing, the sleeve comprising one or
more gripping members on an outer portion of the sleeve configured
to grip a wellbore wall; a drive shaft passing through the tool
housing and having a central gear; at least one drive gear
rotatably coupled to the sleeve, the at least one drive gear
meshing both with an inner portion of the sleeve and with the
central gear; and a pump mechanism coupled to the drive shaft to
receive power imparted by rotation of the drive shaft, the pump
configured to increase a fluid pressure within the flow passage. In
another embodiment, the pump comprises a multi-stage impeller
assembly. In yet another, the at least one drive gear is rotatably
coupled about an axis parallel to an axis of the tool housing.
[0034] In another embodiment of the present disclosure, the tool
further comprises a plurality of teeth along the inner portion of
the rotating sleeve; a plurality of teeth on the at least one drive
gear; and a plurality of teeth on the central gear of the drive
shaft, wherein the teeth on the at least one drive gear mesh both
with the teeth along the inner portion of the rotating sleeve and
the teeth on the central gear. In yet another, the at least one
drive gear comprises a plurality of drive gears circumferentially
spaced about the drive shaft. In another, the tool further
comprises a plurality of offset elements defining a fluid flow
channel about the one or more gripping member.
[0035] Another exemplary embodiment of the present disclosure
provides a tool for boosting fluid pressure downhole, the tool
comprising a tool housing which rotates in relation to a wellbore
wall, the tool housing defining a flow passage in which fluid can
flow; a drive gear comprising: a first friction transfer element
having a portion which extends out from the tool housing and a
portion which extends into the tool housing; and a second friction
transfer element having a portion which extends out from the tool
housing and a portion which extends into the tool housing, wherein
the portions of the first and second friction transfer elements
that extend out from the tool housing grip the wellbore wall to
create a rotational force when the tool housing is rotated; a drive
shaft operationally coupled to the first and second friction
transfer elements whereby, during rotation of the tool housing, the
first and second friction transfer elements transfer the rotational
force to the drive shaft, thereby resulting in rotation of the
drive shaft; and a pump mechanism positioned along the flow passage
and operationally coupled to the drive shaft to thereby receive the
rotational force imparted by the drive shaft, thus driving the pump
mechanism to boost a pressure of fluid traveling through the flow
passage.
[0036] In an alternate embodiment, the first and second friction
transfer elements are friction balls. In yet another, the first and
second friction transfer elements rotate on an axis parallel to an
axis of the tool housing during rotation of the tool housing. In
any of the foregoing embodiments, the wellbore may be cased.
Moreover, in those same exemplary embodiments, the tool forms part
of a drilling or completion assembly.
[0037] An exemplary methodology of the present disclosure provides
a method for boosting fluid pressure in a wellbore, the method
comprising positioning a downhole tool at a desired location along
the wellbore, whereby fluid travels through a flow passage of the
downhole tool; rotating the downhole tool in relation to an
opposing surface to produce a rotational force; and utilizing the
rotational force to drive a pump mechanism to thereby boost a
pressure of the fluid traveling through the downhole tool. Another
method further comprises increasing an annular velocity of the
fluid in response to the pressure boost. In yet another method,
rotating the downhole tool to produce the rotational force further
comprises gripping the opposing surface using a rotating sleeve
positioned around the downhole tool; rotating the downhole tool
while the rotating sleeve remains stationary; rotating a drive gear
operationally coupled to the rotating sleeve in response to
rotation of the downhole tool; and rotating a drive shaft
operationally coupled to the drive gear in response to rotation of
the drive gear. In another, driving the pumping mechanism further
comprises driving the pumping mechanism in response to the rotation
of the drive shaft.
[0038] In yet another method, rotating the downhole tool to produce
the rotational force further comprises gripping the opposing
surface using a friction transfer element positioned along the
downhole tool; rotating the downhole tool; rotating the friction
transfer element in response to rotation of the downhole tool; and
rotating a drive shaft operationally coupled to the friction
transfer element in response to rotation of the friction transfer
element. Another method further comprises forcing the fluid out of
the downhole tool and up through an annulus formed between the
downhole tool and the opposing surface. In another, gripping the
opposing surface further comprises gripping a surface of a casing,
liner or formation. In yet another, positioning the downhole tool
at the desired location along the wellbore further comprises
deploying the downhole tool as part of a drilling or completion
assembly.
[0039] The foregoing disclosure may repeat reference numerals
and/or letters in the various examples. This repetition is for the
purpose of simplicity and clarity and does not in itself dictate a
relationship between the various embodiments and/or configurations
discussed. Further, spatially relative terms, such as "beneath,"
"below," "lower," "above," "upper" and the like, may be used herein
for ease of description to describe one element or feature's
relationship to another element(s) or feature(s) as illustrated in
the figures. The spatially relative terms are intended to encompass
different orientations of the apparatus in use or operation in
addition to the orientation depicted in the figures. For example,
if the apparatus in the figures is turned over, elements described
as being "below" or "beneath" other elements or features would then
be oriented "above" the other elements or features. Thus, the
exemplary term "below" can encompass both an orientation of above
and below. The apparatus may be otherwise oriented (rotated 90
degrees or at other orientations) and the spatially relative
descriptors used herein may likewise be interpreted
accordingly.
[0040] Although various embodiments and methodologies have been
shown and described, the disclosure is not limited to such
embodiments and methodologies and will be understood to include all
modifications and variations as would be apparent to one skilled in
the art. Therefore, it should be understood that the disclosure is
not intended to be limited to the particular forms disclosed.
Rather, the intention is to cover all modifications, equivalents
and alternatives falling within the spirit and scope of the
disclosure as defined by the appended claims.
* * * * *